Copyright By Kelly Joe Harrington 2014 i Carbon Capture and Sequestration and CO2 Enhanced Oil Recovery in the Temblor Formation Sandstones at McKittrick oil field, San Joaquin Valley, California By Kelly Joe Harrington B.S. A Thesis Submitted to the Department of Geological Sciences California State University, Bakersfield In Partial Fulfillment for the Degree of Masters of Science In Geology Fall 2014 ii Acknowledgements I would like to express my deepest appreciation to Dr. Janice Gillespie, my committee chair. She has provided guidance and support for the progress of this research. She has demonstrated much patience and endurance through the revision process as she had to endure many drafts to perfect this work. Without her patience and expertise this thesis would not be. I can’t express the amount of encouragement she has provided to persuade me to quit work and focus on my thesis while providing scholarship opportunities. She was my first Geology professor and will always have a special place in my heart as she has shown me the love of geology. Dr. Negrini provided encouragement and allowed me to be part of the CREST scholarship which provided income that I may concentrate on my education. He has also been an inspiration to complete this work in a timely manner. I would also like to thank Preston Jordan for providing advice and expertise through the making of this work. I would like to thank my committee chairs; Dr. Dayanand Saini and Brian Taylor which have provided much appreciated feedback in refining this thesis. Dr. Dayanand Saini spent countless hours consulting with me to provide a deeper understanding into the engineering aspects of Carbon Capture and Sequestration. Thanks to Joshua Atkins, and Noe Torres who worked hard on obtaining the production data from the historical production records and digitizing the information into a workable excel spreadsheet. Chevron USA has provided consultations to aide in understanding the study area and troubleshooting Petrel issues. They also provided much needed digital logs to assist in this research. I would like to extend a special thank you to my family and God whom have provided the moral support and strength through the most trying times. Without their love and patience I would not have been able to continue this work to its completion. iv Table of Contents Table of Contents v List of Figures vii List of Tables viii List of Appendices viii ABSTRACT ix INTRODUCTION 1 Regional Geology 5 Production History 14 METHODS 17 RESULTS 23 CONCLUSION/DISCUSSION 36 REFERENCES: 38 APPENDICES 41 Appendix A 41 Appendix B 48 v List of Figures Figure 1: San Joaquin Basin map............................................................................................... 6 Figure 2: Generalized stratigraphy column of the San Joaquin Valley ..................................... 8 Figure 3: Southern San Joaquin Basin generalized cross section. .......................................... 11 Figure 4: Phacoides Isopach map with log signatures ........................................................... 13 Figure 5: Type log for well 562 ................................................................................................ 14 Figure 6: Structure map on the top Phacoides ....................................................................... 16 Figure 7: Petrel 3d geological model ..................................................................................... 24 Figure 8: West to east cross-section depicting compartmentalization .................................. 25 Figure 9: Fault block diagram ................................................................................................. 26 Figure 10: Production history by fluid stream graph .............................................................. 29 Figure 11: Well by well production map with isopach ........................................................... 30 Figure 12: Hydrostatic pressure graphs .................................................................................. 32 Figure 13: Spatial analysis of fractional hydrostatic pressure. ............................................... 34 vi List of Tables Table 1: Production and CO2 space available by fault block .................................................. 28 vii List of Appendices Appendix A……………………………………………………………………………...………………………………….41 Appendix B……………………………………………………………………………...………………………………….48 viii Abstract Depleting oil and gas fields are ideal storage sites for atmospheric carbon dioxide because of their large capacities and proven ability to retain fluids for millions of years. In addition, the CO2, when injected at depths greater than 3000 feet, can increase recovery of remaining oil in place by an additional 10% - 20% of the original oil in place (OOIP). This research investigates the possibility of carbon capture and sequestration (CCS) in the Phacoides member of the Temblor Formation in the McKittrick oil field located in the San Joaquin Valley of California. The Phacoides reservoir has produced 71.5 MMRB (million reservoir barrels) of fluid equivalent to approximately 5.8 million tons of CO2. Through CO2 EOR an additional 17 MMBO (million barrels of oil) may be recoverable, thereby offsetting the cost of CCS. Faulting has compartmentalized the reservoir into at least six separate fault blocks requiring at least five separate injection wells in order to fill each of the blocks. The presence of faulting also increases the risk of CO2 leakage. Pressure analysis also revealed the presence of a weak water drive which will fill some of the vacated pore space available for CO2 sequestration—especially along the flanks of the structure. ix Introduction Carbon Capture and Sequestration (CCS) is a promising new technology to help prevent the release of greenhouse gases (GHG’s) into the atmosphere, ultimately delaying the effects of climate change (Sundquist et al., 2008). The global annual emissions of anthropogenic GHG have almost doubled from 1970 to 2004. Most production of GHGs are from energy and industrial sources with CO2 gases making up over 50 percent of the GHGs released (IPCC, 2008). According to atmospheric models developed by the U.S. Climate Change Science Program (CCSP), in order to stabilize an atmospheric C02 level at 550 ppm, global emissions must be reduced by 75 percent over the next century (Sundquist et al., 2008). CCS is the process of capturing carbon dioxide (CO2) at stationary sources that emit high volumes of GHG’s and injecting the gas into underground geologic reservoirs or the deep ocean for permanent storage (Kaldi et al., 2009). Depleted oil and gas reservoirs are ideal storage sites for CO2 because of their proven containment of buoyant fluids (Kaldi et al., 2009). They have been thoroughly studied, providing an abundance of publicly accessible surface and subsurface data and have existing infrastructure already in place that can be adapted for CCS implementation. In 2007, a nationwide study was conducted by the USGS to determine ideal conditions for CCS in depleted oil fields (Burruss et al., 2009). The following criteria were developed for geological storage: 1 1. Formation water salinity of the reservoir cannot be less than 10,000 mg/L TDS. Waters with salinity less than 10,000 mg/L TDS are considered a possible water supply by the U.S. Environmental Protection Agency (EPA) and should be protected from potential sources of contamination. 2. The depth of the reservoir must be 3000 feet or greater. At this depth, the pressure and temperature are sufficient for CO2 to maintain a supercritical fluid state. At these conditions, the density of CO2 is less than water and similar to oil. The CO2 fluid would migrate upward and become trapped in the same structural traps that have retained oil deposits for millions of years. 3. Minimum production of reservoir must be 12.5 MMbbl oil --equivalent to 1-1.4 million metric tons of CO2 at reservoir conditions. The largest constraint on implementing CCS projects is the cost of capturing, transporting and monitoring CO2 (IPPC, 2005). Depleted oil fields have the infrastructure in place to transport and monitor CCS adequately. However, the current technology for CO2 capture is not economically viable for mass production and installation. Current costs of CCS are estimated to be as much as $31/ton (Myers et al., 2006). This does not include the cost of retrofitting a power plant to capture CO2 since the cost can vary greatly depending on the type and amount of emissions produced (Myers et al., 2008). The cost of CCS can be offset by turning the waste carbon dioxide into a commodity for CO2 EOR. Thus, storing CO2 in depleted oil reservoirs is a good starting point for the ultimate goal of larger scale storage in higher volume saline aquifers (IPCC, 2005). 2 In many mature oil fields, much of the remaining oil in place has not been recovered under primary and secondary methods. The use of CO2 EOR has resulted in recovery rates as high as 10-20% of the original oil in place (OOIP) (Enick and Olsen, 2012). Most current CO2 EOR projects in the US lie within the Permian basin of west Texas where natural sources of CO2 are readily available (Advanced Resources International, 2006). It is estimated that over 57.3 million barrels of residual oil in California are stranded in mature reservoirs and 6.3 million may be recoverable by CO2 EOR (The National Energy Laboratory, 2009). A typical CO2 EOR process consists of injecting slugs of CO2 chased by water slugs to push the comingled fluid toward